and Chief Nuclear Officer TXU Power ATTN: Regulatory ... · July 22, 2006 Mike Blevins, Senior Vice...

July 22, 2006

Mike Blevins, Senior Vice President and Chief Nuclear OfficerTXU PowerATTN: Regulatory Affairs Comanche Peak Steam Electric StationP.O. Box 1002Glen Rose, TX 76043

SUBJECT: COMANCHE PEAK STEAM ELECTRIC STATION - NRC INTEGRATEDINSPECTION REPORT 05000445/2006003 AND 05000446/2006003

Dear Mr. Blevins:

On June 23, 2006, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection atyour Comanche Peak Steam Electric Station, Units 1 and 2 facility. The enclosed integratedinspection report documents the inspection findings which were discussed on June 29, 2006,with you and other members of your staff.

This inspection examined activities conducted under your licenses as they related to safety andcompliance with the Commission's rules and regulations and with the conditions of yourlicenses. The inspectors reviewed selected procedures and records, observed activities, andinterviewed personnel.

This report documents two NRC-identified findings of very low safety significance (Green). Both findings were determined to involve violations of NRC requirements. However, because oftheir very low safety significance and because they were entered into your corrective actionprogram, the NRC is treating the findings as noncited violations (NCV) consistent withSection VI.A.1 of the NRC Enforcement Policy. If you contest any NCV in this report, youshould provide a response within 30 days of the date of this inspection report, with the basis foryour denial, to the U.S. Nuclear Regulatory Commission, ATTN.: Document Control Desk,Washington DC 20555-0001; with copies to the Regional Administrator, Region IV; the Director,Office of Enforcement, United States Nuclear Regulatory Commission, Washington DC 20555-0001; and the NRC Resident Inspector at Comanche Peak Steam Electric Station.

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and itsenclosure will be made available electronically for public inspection in the NRC PublicDocument Room or from the Publicly Available Records (PARS) component of NRC’sdocument system (ADAMS). ADAMS is accessible from the NRC Web site athttp://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

TXU Power -2-

Should you have any questions concerning this inspection, we will be pleased to discuss themwith you.

Sincerely,

/RA/

Claude Johnson, ChiefProject Branch ADivision of Reactor Projects

Docket Nos.: 50-445, 50-446License Nos.: NPF-87, NPF-89

Enclosure: NRC Inspection Report 05000445/2006003 and 05000446/2006003 w/Attachment: Supplemental Information

cc w/Enclosure:Fred W. Madden, DirectorRegulatory Affairs TXU PowerP.O. Box 1002Glen Rose, TX 76043

George L. Edgar, Esq.Morgan Lewis1111 Pennsylvania Avenue, NWWashington, DC 20004

Terry Parks, Chief InspectorTexas Department of Licensing and RegulationBoiler ProgramP.O. Box 12157Austin, TX 78711

The Honorable Walter MaynardSomervell County JudgeP.O. Box 851Glen Rose, TX 76043

Richard A. Ratliff, ChiefBureau of Radiation Control Texas Department of Health1100 West 49th StreetAustin, TX 78756-3189

TXU Power -3-

Environmental and Natural Resources Policy DirectorOffice of the GovernorP.O. Box 12428Austin, TX 78711-3189

Brian AlmonPublic Utility CommissionWilliam B. Travis BuildingP.O. Box 13326Austin, TX 78711-3326

Susan M. JablonskiOffice of Permitting, Remediation and RegistrationTexas Commission on Environmental QualityMC-122P.O. Box 13087Austin, TX 78711-3087

ChairpersonDenton Field Office Chemical and Nuclear Preparedness and Protection DivisionOffice of Infrastructure ProtectionPreparedness DirectorateDept. of Homeland Security800 North Loop 288Federal Regional CenterDenton, TX 76201-3698

Technological Services BranchChiefFEMA Region VI800 North Loop 288Federal Regional CenterDenton, Texas 76201-3698

TXU Power -4-

Electronic distribution by RIV:Regional Administrator (BSM1)DRP Director (ATH)DRS Director (DDC)DRS Deputy Director (RJC1)Senior Resident Inspector (DBA)Branch Chief, DRP/A (CEJ1)Senior Project Engineer, DRP/A (TRF)Team Leader, DRP/TSS (RLN1)RITS Coordinator (KEG)DRS STA (DAP)J. Lamb, OEDO RIV Coordinator (JGL1)ROPreportsCP Site Secretary (ESS)Regional State Liaison Officer (WAM)NSIR/DPR/EPD (REK)DMB (IE35)

SUNSI Review Completed: __CEJ_ADAMS: / Yes G No Initials: ___CEJ___ / Publicly Available G Non-Publicly Available G Sensitive / Non-Sensitive

R:\_REACTORS\_CPSES\2006\CP2006-03RP-DBA.wpdRIV:RI:DRP/A SRI:DRP/A C:DRS/EB C:DRS/OB C:DRS/PEB C:DRS/PSBAASanchez DBAllen JAClark ATGody LJSmith MPShannon

E-CEJ E-CEJ /RA/ RELantz for /RA/ /RA/7/14/06 7/14/06 7/10/06 7/12/06 7/12/06 7/10/06

C:DRP/ACEJohnson

/RA/7/22/06

OFFICIAL RECORD COPY T=Telephone E=E-mail F=Fax

U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Dockets: 50-445, 50-446

Licenses: NPF-87, NPF-89

Report: 05000445/2006003 and 05000446/2006003

Licensee: TXU Generation Company LP

Facility: Comanche Peak Steam Electric Station, Units 1 and 2

Location: FM-56, Glen Rose, Texas

Dates: March 25, 2006 through June 23, 2006

Inspectors: D. Allen, Senior Resident InspectorA. Sanchez, Resident InspectorP. Elkmann, Emergency Preparedness InspectorP. Goldberg, Reactor Inspector, Engineering Branch 2R. Lantz, Senior Emergency Preparedness InspectorM. Murphy, Senior Operations EngineerG. Pick, Senior Reactor Inspector, Engineering Branch 2B. Tharakan, Health Physicist, Plant Support BranchG. Werner, Senior Project Engineer, Branch DJ. Keeton, Consultant

Approved by: Claude Johnson, Chief, Project Branch ADivision of Reactor Projects

Attachment: Supplemental Information

Enclosure-2-

TABLE OF CONTENTS

SUMMARY OF FINDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -3-

REPORT DETAILS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -5-

REACTOR SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -5-1R01 Adverse Weather Protection (71111.01) . . . . . . . . . . . . . . . . . . . . . . . . . . . . -5-1R04 Equipment Alignment (71111.04) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -5-1R05 Fire Protection (71111.05Q) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -6-1R06 Flood Protection Measures (71111.06) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -7-1R07 Heat Sink Performance (71111.07) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -7-1R11 Licensed Operator Requalification Program (71111.11) . . . . . . . . . . . . . . . . -8-1R12 Maintenance Effectiveness (71111.12) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -9-1R13 Maintenance Risk Assessments and Emergent Work Evaluation (71111.13) -11-1R15 Operability Evaluations (71111.15) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -11-1R19 Postmaintenance Testing (71111.19) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -12-1R22 Surveillance Testing (71111.22) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -13-1EP4 Emergency Action Level and Emergency Plan Changes (71114.04) . . . . . -14-1EP6 Drill Evaluation (71114.06) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -15-

RADIATION SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -15-2OS1 Access Control to Radiologically Significant Areas (71121.01) . . . . . . . . . . -16-2OS2 ALARA Planning and Controls (71121.02) . . . . . . . . . . . . . . . . . . . . . . . . . -18-

OTHER ACTIVITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -19-4OA1 Performance Indicator Verification (71151) . . . . . . . . . . . . . . . . . . . . . . . . . -19-4OA2 Problem Identification and Resolution (71152) . . . . . . . . . . . . . . . . . . . . . . -21-4OA3 Event Followup (71153) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -23-4OA5 Other Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -24-4OA6 Meetings, Including Exit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -27-

SUPPLEMENTAL INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1

KEY POINTS OF CONTACT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1

ITEMS OPENED, CLOSED, AND DISCUSSED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1

LIST OF DOCUMENTS REVIEWED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-2

LIST OF ACRONYMS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-7

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SUMMARY OF FINDINGS

IR 05000445/2006003, 05000446/2006003; 03/25/2006-06/23/2006; Comanche Peak SteamElectric Station, Units 1 and 2. Access Control to Radiologically Significant Areas and OtherActivities.

This report covered a 3-month period of inspection by two resident inspectors, two emergencypreparedness inspectors, one health physicist, two engineering inspectors, one senioroperations engineer, and one consultant. Two Green findings, both of which were NCVs, wereidentified. The significance of most findings is indicated by their color (Green, White, Yellow, orRed) using the Inspection Manual Chapter 0609, “Significance Determination Process.” Findings for which the Significance Determination Process does not apply may be Green or beassigned a severity level after NRC management review. The NRC's program for overseeingthe safe operation of commercial nuclear power reactors is described in NUREG-1649,?Reactor Oversight Process,” Revision 3, dated July 2000.

A. NRC-Identified and Self-Revealing Findings

Cornerstone: Mitigating Systems

• Green. The team identified a Green noncited violation of License Condition 2.Gand Technical Specification 5.4.1.d for failure to complete simulated operatoractions within analyzed times and for the inability to perform some of therequired actions with five examples. Specifically, the following deficiencies wereidentified: (1) the shift manager was unable to easily obtain the keys needed toaccess the transfer and hot shutdown panels, which delayed taking the requiredactions; (2) directions for starting the safety chiller, if not already operating, werenot provided, which could have delayed accomplishing the task; (3) the licenseehad not accounted for 1.5 minutes needed by operators to perform requiredactions prior to evacuating the control room; (4) operators took 4 minutes tomitigate a spuriously open power-operated relief valve, whereas, the analysisused 3 minutes; and (5) the 3.5 minutes needed to don the flash protective gearprevented completion of subsequent procedure steps within the time analyzed. The cause of the finding is related to the crosscutting aspect of humanperformance because: (1) operations personnel were unfamiliar with proceduresand did not have some pertinent procedure steps available, and (2)organizations failed to communicate changes to the procedure that impacted theresponse time.

The team determined that this finding had more than minor significance becausethe inadequate procedure impacted the mitigating systems cornerstone andaffected the cornerstone objective to ensure the availability, reliability, andcapability of the system that responds to the event to prevent undesirableconsequences. A Phase 3 analysis of the above issues concluded the findingwas of very low risk significance. Specifically, the Phase 3 analysis concludedthat the 8-minute delay in transferring equipment from the control room and anadditional 10-minute delay in accessing the remote shutdown room, did notresult in a significant increase in risk. The analyst determined that a hot-short to

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a power operated relief valve was the most risk significant situation. The riskassociated with a stuck open power-operated relief valve combined with a fire inthe control room panel not suppressed was determined to be 2.7E-11/year. Theanalyst concluded that it would require a 22 percent increase in the stress levelsof the operators to result in the risk exceeding the threshold to be consideredgreater than that of very low risk significance (Section 4OA5).

Cornerstone: Occupational Radiation Safety

• Green. The inspector identified three examples of a noncited violation of10 CFR 20.1902(a) because the licensee failed to conspicuously post a radiationarea. Specifically, on May 18, 2006, two discrete radiation areas in the fuelbuilding and one in the auxiliary building were identified as not beingconspicuously posted. The highest general area dose rate was 15 millirem perhour. The licensee conspicuously posted these areas and entered the findinginto their corrective action program as Smart Form SMF-2006-001787-00.

The finding was greater than minor because it was associated with theOccupational Radiation Safety Cornerstone attribute of Program and Processand affected the cornerstone objective to ensure the adequate protection of aworker’s health and safety from exposure to radiation because not alertingworkers to the presence of radiation could prevent them from taking measures tominimize radiation exposure. The finding was processed through theOccupational Radiation Safety Significance Determination Process anddetermined to be of very low safety significance because it was not an as low asreasonably achievable finding, there was no overexposure or substantialpotential for an overexposure, and the ability to assess dose was notcompromised (Section 2OS1).

B. Licensee-Identified Violations

None.

Enclosure-5-

REPORT DETAILS

Summary of Plant Status

Comanche Peak Steam Electric Station (CPSES) Units 1 and 2 operated at essentially100 percent power for the entire reporting period.

1. REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection (71111.01)

a. Inspection Scope

The inspectors reviewed Abnormal Conditions Procedure Manual (ABN) ABN-907, “Actsof Nature,” Revision 10, in the Unit 1 control room in anticipation of severe weatherconditions (thunderstorms and high winds) predicted for the weekend ofMay 5 - 7, 2006. The inspectors interviewed the work week coordinator to determine thescheduled work activities and the potential risk impact due to the weather. OnMay 5, 2006, the inspectors performed a walkdown of the exterior areas of the protectedarea to assess the plant’s readiness for high wind velocities, including the materialstaged in the laydown areas and the status of missile shields, access hatches andexterior doors. The Smart Form (SMF) data base was reviewed for weather relatedproblems that could impact mitigating systems and their support systems to determine ifthe problems had been properly addressed for resolution.

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment (71111.04)

a. Inspection Scope

The inspectors: (1) walked down portions of the below listed risk important systems andreviewed plant procedures and documents to verify that critical portions of the selectedsystems were correctly aligned; and (2) compared deficiencies identified during thewalkdown to the licensee's corrective action program to ensure problems were beingidentified and corrected.

• Unit 2 Turbine Driven Auxiliary Feedwater (TDAFW) system in accordance withOperations Testing Manual (OPT) Procedure OPT-206B, “AFW System,”Revision 18 while Emergency Diesel Generator (EDG) 2-01 was inoperable forscheduled maintenance and surveillance testing on April 5, 2006

Enclosure-6-

C Unit 2 Train A EDG system in accordance with System Operating Procedure(SOP) SOP-609B, “Diesel Generator System,” Revision 9 while the Train B EDGsystem was inoperable for scheduled surveillance on April 19, 2006

C Unit 1 Train B EDG system in accordance with SOP-609A, “Diesel GeneratorSystem,” Revision 17 while the TDAFW pump was inoperable for speed drooptroubleshooting activities on April 25, 2006

The inspectors completed three samples.

b. Findings


1R05 Fire Protection (71111.05Q)

Fire Area Tours

a. Inspection Scope

The inspectors walked down the listed plant areas to assess the materiel condition ofactive and passive fire protection features and their operational lineup and readiness. The inspectors: (1) verified that transient combustibles and hot work activities werecontrolled in accordance with plant procedures; (2) observed the condition of firedetection devices to verify they remained functional; (3) observed fire suppressionsystems to verify they remained functional; (4) verified that fire extinguishers and hosestations were provided at their designated locations and that they were in a satisfactorycondition; (5) verified that passive fire protection features (electrical raceway barriers,fire doors, fire dampers, steel fire proofing, penetration seals, and oil collection systems)were in a satisfactory materiel condition; (6) verified that adequate compensatorymeasures were established for degraded or inoperable fire protection features; and(7) reviewed the corrective action program to determine if the licensee identified andcorrected fire protection problems.

C Fire Zone EN064 - Unit 1 cable spreading room on April 20, 2006

C Fire Zone EM063 - Unit 2 cable spreading room on April 20, 2006

C Fire Zone EA0043 - steam generator blowdown room on April 21, 2006

C Fire Zone 1SB02A - Unit 1 Train A emergency core cooling pump rooms,773 foot elevation, on May 10, 2006

C Fire Zone 1SB015 - Unit 1 containment access corridor, 831 foot elevation, onMay 10, 2006

C Fire Zone 2SB015 - Unit 2 containment access corridor, 831 foot elevation, onMay 11, 2006

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C Fire Zone AA21A - Units 1 & 2 auxiliary building, 790 foot elevation, onJune 4, 2006

The inspectors completed seven samples.

b. Findings


1R06 Flood Protection Measures (71111.06)

External Flood Protection

a. Inspection Scope

The inspectors: (1) reviewed the Updated Safety Analysis Report, the Design BasisDocument DBD-CS-071, “Probable Maximum Flood (PMF),” Revision 10, and theapplicable plant procedure ABN-907, “Acts of Nature,” Revision 10, to assess theCPSES site’s susceptibility to external flooding; (2) reviewed the corrective actionprogram to determine if the licensee identified and corrected flooding problems; and(3) on April 14, 2006, walked down the areas of the plant below grade level to verify theadequacy of equipment seals and floor and wall penetration seals located below themaximum flood level.


b. Findings


1R07 Heat Sink Performance (71111.07)

a. Inspection Scope

The inspectors reviewed the licensee’s program for maintenance and testing for thethree risk-important heat exchangers listed below. The inspectors performed the reviewto ensure that these heat exchangers are capable of performing their required safetyfunction during the design basis accident. Specifically, the inspectors observed thephysical condition before and after cleaning activities and verified that the frequency ofmonitoring and inspection was sufficient to detect degradation prior to loss of heatremoval capabilities below design requirements. Corrective action documents anddesign basis documents were also reviewed by the inspectors. The service watersystem and fouling monitoring program manager was also interviewed. The followingheat exchangers were reviewed for this inspection:

C On February 16, 2006 the inspectors observed and reviewed the cleaning of theUnit 2 Containment Spray Pump 2-04 lube oil coolers.

Enclosure-8-

C On March 23, 2006, the inspectors interviewed the system engineer andreviewed photographs of the Unit 1 Safety Injection Pump (SIP) 1-02 lube oilcooler.

C On April 25, 2006, the inspectors observed the as found, cleaning, and as leftcondition of the Unit 2 SIP 2-01 lube oil cooler.

The inspectors completed three samples.

b. Findings


1R11 Licensed Operator Requalification Program (71111.11)

.1 Resident Inspector Quarterly Review (71111.11Q)

a. Inspection Scope

The inspector observed a licensed operator requalification training scenario in thecontrol room simulator on April 27, 2006. The scenario began with a short event torecognize a reactor coolant pump under-frequency trip and take appropriate actions tomanually trip the reactor. The main scenario began with operators taking the watch withthe reactor at 100 percent power. The following events then took place: (1) steamgenerator transmitter failed high; (2) steam generator tube leak; (3) steam generatorfeedwater regulating valve failed close, (4) required reactor trip and safety injection; and(5) a steam generator tube rupture and a Loss of Coolant Accident with subcooledrecovery.

Simulator observations included formality and clarity of communications, groupdynamics, the conduct of operations, procedure usage, command and control, andactivities associated with the emergency plan. The inspectors also verified thatevaluators and the operators were identifying crew performance problems as applicable.

On April 24, 2006 a classroom session on the upcoming steam generator and reactorvessel head was also attended.


b. Findings


Enclosure-9-

.2 Regional Biennial Review

a. Inspection Scope

Following the completion of the annual operating examination testing cycle, which endedthe week of March 27, 2006, the inspector reviewed the overall pass/fail results of theannual individual job performance measure operating tests, and simulator operatingtests administered by the licensee during the operator licensing requalification cycle. Fourteen separate crews participated in simulator operating tests, and job performancemeasure operating tests, totaling 83 licensed operators. All of the crews tested passedthe simulator portion of the annual operating test. All of the licensed operators passedthe job performance measure portion of the examination.

b. Findings


1R12 Maintenance Effectiveness (71111.12)

.1 Routine Maintenance Effectiveness Inspection

a. Inspection Scope

The inspectors independently verified that CPSES personnel properly implemented10 CFR 50.65, “Requirements for Monitoring the Effectiveness of Maintenance atNuclear Power Plants,” for the following equipment performance items:

C Recent functional failures of Unit 2 Safety Chiller 2-06, and reviews ofunavailability and issues of associated safety chillers in both units and bothtrains. The more pertinent issues were entered into the licensee’s correctiveaction program as SMF-2006-002124-00 and SMF-2006-001814-00.

C Units 1 and 2 containment spray systems related SMFs and performance issues,including maintenance activities that resulted in greater unavailability time thanscheduled, system leaks, repeated unavailability due to low flow to pump bearingcoolers from station service water, and degraded pipe wall in Containment SprayPump 1-04 pump casing drain pipe.

The inspectors reviewed whether the structures, systems, or components (SSCs) thatexperienced problems were properly characterized in the scope of the MaintenanceRule Program and whether the SSC failure or performance problem was properlycharacterized. The inspectors assessed the appropriateness of the performance criteriaestablished for the SSCs where applicable. The inspectors also independently verifiedthat the corrective actions and responses were appropriate and adequate.

The inspectors completed two samples.

Enclosure-10-

b. Findings


.2 Triennial Review

a. Inspection Scope

Periodic Evaluation Reviews

The inspectors reviewed the licensee’s overall implementation of the Maintenance Rule,10 CFR 50.65, "Requirements for Monitoring the Effectiveness of Maintenance atNuclear Power Plants." The inspectors reviewed scope and depth of the licensee'sMaintenance Rule periodic assessments for May 22, 2003, to February 20, 2005. Theinspectors then assessed the effectiveness of corrective actions and programadjustments as a result of the assessment findings.

The inspectors also selected samples of four SSCs within the scope of the licensee’sMaintenance Rule program that had degraded performance at some point during thereview period. These samples were used to assess the licensee’s response to thedegraded performance within the scope of the Maintenance Rule program. InspectionProcedure 71111.12B requires that the inspector review four to six SSC samples. Theinspectors selected the following four samples for a detailed review:

• Station Service Water System• Reactor Protection System• Component Cooling Water System• Main Steam System

For these SSCs, the inspectors reviewed the use of performance history and operatingexperience, both internal and industry wide, in adjusting preventive maintenance,(a)(1) goals, and (a)(2) performance criteria. For structures being monitored throughcondition monitoring, the inspectors reviewed the licensee’s performance criteria andcondition monitoring procedures to determine whether there was consistency andmonitoring of proper attributes which would be predictive of degradation. The inspectorsalso reviewed adjustments to the scope of the Maintenance Rule program and changesmade during the assessment period.

The inspectors completed four samples.

b. Findings


Enclosure-11-

1R13 Maintenance Risk Assessments and Emergent Work Evaluation (71111.13)

a. Inspection Scope

The inspectors reviewed selected activities regarding risk evaluations and overall plantconfiguration control. The inspectors discussed emergent work issues with work controlpersonnel and reviewed the potential risk impact of these activities to verify that the work was adequately planned, controlled, and executed. The activities reviewedwere associated with:

C The unexpected Electric Reliability Council of Texas (ERCOT) implementation oftheir emergency electric curtailment plan due to extremely warm temperaturesresulting in electrical line overloads throughout the Texas grid onApril 17-18, 2006

C Postponement of Unit 1 TDAFW pump run due to severe weather onApril 20, 2006

C Escalation of the Unit 1 risk to Red due to unexpected severe thunderstormwarnings while the TDAFW pump was inoperable for troubleshooting activitieson April 25, 2006

C Emergent work on Unit 1 TDAFW pump (replaced governor and current topneumatic (I/P) converter) which caused rescheduling of SIP 1-01 maintenanceon May 2, 2006

C A trip of Unit 2 Safety Chiller 2-06 (Train B) during a Train A maintenance workweek, which led to start of the Train A safety chiller and realignment of reactorcoolant system charging, spent fuel pool cooling, and control room airconditioning system cooling on June 19-20, 2006

The inspectors completed five samples.

b. Findings


1R15 Operability Evaluations (71111.15)

a. Inspection Scope

The inspectors: (1) reviewed plant status documents such as operator shift logs,emergent work documentation, deferred modifications, and standing orders todetermine if an operability evaluation was warranted for degraded components;(2) referred to the Updated Safety Analysis Report and design basis documents toreview the technical adequacy of licensee operability evaluations; (3) evaluatedcompensatory measures associated with operability evaluations; (4) determineddegraded component impact on any Technical Specifications; (5) used the significance

Enclosure-12-

determination process (SDP) to evaluate the risk significance of degraded or inoperableequipment; and (6) verified that the licensee has identified and implemented appropriatecorrective actions associated with degraded components. The inspectors interviewedappropriate licensee personnel to provide clarity to operability evaluations, asnecessary. Specific operability evaluations reviewed are listed below:

C SMF-2006-001290-00, following maintenance on the Unit 1 Containment SprayPump 1-03, a 30 drop per minute leak was discovered in the threaded stationservice water pipe connection to the outboard bearing oil cooler of the pump,reviewed on April 23, 2006

C Evaluation (EVAL) 2006-001177-01-00, determine effects on operability andplant design of removing approximately 8 inches of piping insulation on an 8-inchline SI-2-037 in Room 2-062E, specifically the environmental qualification of theequipment in the room, reviewed on June 4, 2006

C EVAL-2006-001178-01-00, determine operability of Component CoolingWater (CCW) Pump 1-02 Recirculation Flow Valve 1-FV-4537 after it exceededthe Alert and Acceptance stroke time criteria per OPT-208A, “CCW System,”Revision 11, reviewed on June 4, 2006

C EVAL 2006-001714-01-00, engineering determined acceptability of designqualification of the spent fuel pool gates with gaps up to 1/16-inch between thenew washers and the gate hinges, reviewed the week of June 4, 2006

C Quick Technical Evaluation QTE-2006-000972-01-03, Unit 1 TDAFW pumpturbine speed control drift issue following troubleshooting that yielded moreinformation on possible equipment problems, reviewed the weeks ofApril 25, 2006, and June 12, 2006

C EVAL-2006-000976-03, Unit 1 TDAFW Pump 1-01 Discharge to SteamGenerator 1-01 Isolation Valve 1-HV-2491-A after failing the “as found,”surveillance for thrust criteria, reviewed on June 23, 2006

The inspectors completed six samples.

b. Findings


1R19 Postmaintenance Testing (71111.19)

a. Inspection Scope

The inspectors witnessed or reviewed the results of the postmaintenance tests for thefollowing maintenance activities:

Enclosure-13-

C Unit 1 Centrifugal Charging Pump 1-01 following the motor breaker replacement,in accordance with OPT-201A, “Charging System,” Revision 13, onMarch 28, 2006

C Unit 1 Atmospheric Relief Valve 1-PV-2327 following the replacement of the I/Pconverter, in accordance with OPT-504A, “MS Section XI Valves,” Revision 11,on April 3, 2006

C Unit 1 Containment Fan Coolers 1 & 2 condensate fill rate Channel 5163following the replacement of lead-lag and power supply cards, in accordancewith Instrument and Control Manual (INC) procedures INC-2301, “Alignment andFunctional Test Westinghouse 7300 Series Lead/Lag Amplifier (NLL) Card,”Revision 3 and INC-7849-A, “Channel Calibration Containment AircoolerCondensate Flowrate Channel 5162/63,” Revision 2, on April 7, 2006

C Unit 2 SIP 2-01 following annual maintenance on the lube oil cooler, inaccordance with OPT-204B, “SI System,” Revision 10, on April 25, 2006

C Unit 1 TDAFW pump following replacement of the governor valve and I/Pconverter to correct a speed drift issue, in accordance with OPT-206A, “AFWSystem,” Revision 25, on May 2, 2006

C Unit 1 Main Steam Line Loop 2 calibration following replacement of the failedpower supply card, in accordance with INC-7301A, “Analog Channel OperationalTest and Channel Calibration Steam Pressure, Loop 2, Protection Set III,Channel 0526,” Revision 6, on June 2, 2006

In each case, the associated work orders and test procedures were reviewed inaccordance with the inspection procedure to determine the scope of the maintenanceactivity and to determine if the testing was adequate to verify equipment operability.

The inspectors completed six samples.

b. Findings


1R22 Surveillance Testing (71111.22)

a. Inspection Scope

The inspectors evaluated the adequacy of periodic testing of important nuclear plantequipment, including aspects such as preconditioning, the impact of testing during plantoperations, and the adequacy of acceptance criteria. Other aspects evaluated includedtest frequency and test equipment accuracy, range, and calibration; procedureadherence; record keeping; the restoration of standby equipment; test failure

Enclosure-14-

evaluations; system alarm and annunciator functionality; and the effectiveness of thelicensee’s problem identification and correction program. The following surveillance testactivities were observed and/or reviewed by the inspectors:

C Unit 2 Containment Spray Pumps 2-01 and 2-03 in accordance with OPT-205B,“Containment Spray System,” Revision 13, observed on March 29, 2006

C Unit 2 Train A residual heat removal system in accordance with OPT-203B,“Residual Heat Removal System,” Revision 11, observed on April 6, 2006

C Unit 2 Containment Recirculation Sumps Trains A and B in accordance withOPT-306, “Containment Sump Inspection,” Revision 6, observed on April 7and 21, 2006

C Unit 1 Train B EDG operability test in accordance with OPT-214A, “DieselGenerator Operability Test,” Revision 18, and OPT-491A, “Train B SafeguardsSlave Relay K609 Actuation Test,” Revision 4, observed on April 12, 2006

C Unit 2 TDAFW pump in accordance with OPT-206B, “AFW System,”Revision 18, observed on April 13, 2006

C Unit 2 monthly core physics testing in accordance with Nuclear EngineeringManual (NUC) procedure NUC-201, “Surveillance of Core Power DistributionFactors,” Revision 12, NUC-203, “Incore/Excore Detector Calibration,”Revision 16, NUC-204, “Target Axial Flux Difference,” Revision 16, and NUC-205, “Core Reactivity Balance,” Revision 10, reviewed on April 17,18, and 23,2006

C Unit 2 Train B CCW operability test in accordance with OPT-208B, “CCWSystem,” Revision 9, observed on June 4, 2006

The inspectors completed seven samples.

b. Findings


Cornerstone: Emergency Preparedness

1EP4 Emergency Action Level and Emergency Plan Changes (71114.04)

a. Inspection Scope

The inspector performed in-office reviews of Revision 33 to the Comanche Peak, Units 1and 2, Emergency Plan, and Revision 11-1 to Emergency Plan Procedure EPP-201,“Assessment of Emergency Action Levels Emergency Classification and PlanActivation,” both submitted in February 2006.

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These revisions changed emergency classification level descriptions and revisedemergency action levels as described in NRC Bulletin 2005-002, "EmergencyPreparedness and Response Actions for Security-Based Events," updated the Letters ofAgreement, and made other editorial changes.

These revisions were compared to their previous revisions, to the criteria ofNUREG-0654, “Criteria for Preparation and Evaluation of Radiological EmergencyResponse Plans and Preparedness in Support of Nuclear Power Plants,” Revision 1, toNuclear Energy Institute (NEI) 99-01, “Methodology for Development of EmergencyAction Levels,” Revision 2, to NRC Bulletin 2005–02, and to the requirements of10 CFR 50.47(b) and 50.54(q), to determine if the licensee adequately implemented10 CFR 50.54(q).

This review was not documented in a Safety Evaluation Report and did not constituteapproval of licensee changes, therefore these changes are subject to future inspection.

The inspector completed two samples during this inspection.

b. Findings


1EP6 Drill Evaluation (71114.06)

a. Inspection Scope

The resident inspectors evaluated the conduct of a routine licensee emergency drill onApril 5, 2006, to identify any weaknesses and deficiencies in classification, notification,and protective action recommendation (PAR) development activities. The scenarioincluded opportunities for classification, notification, and PAR development to becounted towards the licensee Drill/Exercise Performance (DEP) performance indicator. The inspectors observed activities in the control room simulator, technical supportcenter, and the emergency operations center. The inspectors reviewed the scenarioand drill objectives, observed the licensee’s critique to verify that the licensee wasadequately conducting drills and critiquing drill performance.

The inspector completed one sample.

b. Findings


2. RADIATION SAFETY

Cornerstone: Occupational Radiation Safety

Enclosure-16-

2OS1 Access Control to Radiologically Significant Areas (71121.01)

a. Inspection Scope

This area was inspected to assess the licensee’s performance in implementing physicaland administrative controls for airborne radioactivity areas, radiation areas, highradiation areas, and worker adherence to these controls. The inspector used therequirements in 10 CFR Part 20, the Technical Specifications, and the licensee’sprocedures required by Technical Specifications as criteria for determining compliance. During the inspection, the inspector interviewed the radiation protection manager,radiation protection supervisors, and radiation workers. The inspector performedindependent radiation dose rate measurements and reviewed the following items:

• Performance indicator events and associated documentation packages reportedby the licensee in the Occupational Radiation Safety Cornerstone

• Controls (surveys, posting, and barricades) of radiation, high radiation, orairborne radioactivity areas

• Radiation work permits, procedures, engineering controls, and air samplerlocations

• Conformity of electronic personal dosimeter alarm set points with surveyindications and plant policy; workers’ knowledge of required actions when theirelectronic personnel dosimeter noticeably malfunctions or alarms

• Self-assessments, audits, licensee event reports, and special reports related tothe access control program since the last inspection

• Radiation work permit briefings and worker instructions

• Adequacy of radiological controls such as, required surveys, radiation protectionjob coverage, and contamination controls during job performance

The inspector completed 8 of the required 21 samples.

b. Findings

Introduction: The inspector identified three examples of a noncited violation (NCV) of10 CFR 20.1902(a) because the licensee failed to conspicuously post a radiation area. The violation had very low safety significance.

Description: On May 18, 2006, the inspector toured the Instrument and Calibration HotLab, Room X-165, on the 790-foot elevation of the auxiliary building, and identifiedradiation dose rates in excess of 5 millirem per hour from pipe at the top of the stairwayleading to the 802-foot elevation of the fuel building. The dose rates were later

Enclosure-17-

confirmed by the licensee to be up to 30 millirem per hour at 30 cm from this pipe. Thisarea was not conspicuously posted as a radiation area, although the entrance toRoom X-165 was posted on the 790-foot elevation. This room was large enough thatposting the discrete radiation area at the top of the stairway was warranted.

The second and third examples were identified during tours and subsequent review ofsurvey maps of the fuel building. The licensee had posted the entire fuel building as aradiation area. However, posting the entire fuel building was not warranted because thelicensee’s surveys showed that there were two separate and discrete radiation areas inthe fuel building. One radiation area was located on the 810-foot elevation corridor inthe drum storage area, which had maximum dose rates of 10 millirem per hour at30 centimeters. The second location was on the 800-foot elevation in Room X-247, thedrum storage pit, which had maximum dose rates of 15 millirem per hour at30 centimeters.

The inspector reviewed the applicable guidance in NUREG/CR-5569, Revision 1, HealthPhysics Positions 036, “Posting of Entrances to a Large Room or Building as aRadiation Area,” and 066, “Guidance for Posting Radiation Areas.” Because each ofthese examples were discrete radiation areas, the inspector concluded that posting theentire fuel building and the doorway to Room X-165, rather than each discrete radiationarea, was not sufficient to alert radiation workers to radiological hazards in theirimmediate work areas.

Analysis: The failure to conspicuously post a radiation area is a performance deficiency. The finding was greater than minor because it was associated with the OccupationalRadiation Safety Cornerstone attribute of Program and Process and affected thecornerstone objective to ensure the adequate protection of a worker’s health and safetyfrom exposure to radiation because not alerting workers to the presence of radiationcould prevent them from taking measures to minimize radiation exposure. Because thefinding involved the potential for unplanned, unintended dose resulting from conditionsthat were contrary to NRC regulations, the finding was evaluated using the OccupationalRadiation Safety SDP. The finding was determined to be of very low safety significancebecause: (1) it did not involve as low as reasonably achievable (ALARA) planning orwork controls, (2) there was no personnel overexposure, (3) there was no substantialpotential for personnel overexposure, and (4) the finding did not compromise thelicensee’s ability to assess dose.

Enforcement: 10 CFR 20.1003 defines a radiation area as an area, accessible toindividuals, in which radiation levels could result in an individual receiving a doseequivalent in excess of 5 millirem in an hour at 30 centimeters from the radiation sourceor from any surface that the radiation penetrates. 10 CFR 20.1902(a) requires eachradiation area be posted with a conspicuous sign or signs. Contrary to this requirement,on May 18, 2006, the licensee failed to conspicuously post three discrete radiationareas. This violation was entered into the licensee’s corrective action program asSMF-2006-001787-00. Because this finding is of very low safety significance and wasentered into the licensee’s corrective action program, it is being treated as a noncitedviolation, consistent with Section VI.A.1 of the NRC Enforcement Policy: NCV 05000445;446/2006003-01, Three Examples of a Failure to Conspicuously Post aRadiation Area.

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2OS2 ALARA Planning and Controls (71121.02)

a. Inspection Scope

The inspector assessed licensee performance with respect to maintaining individual andcollective radiation exposures ALARA. The inspector used the requirements in10 CFR Part 20 and the licensee’s procedures required by Technical Specifications ascriteria for determining compliance. The inspector interviewed licensee personnel andreviewed:

• Current 3-year rolling average collective exposure

• Five outage work activities scheduled during the inspection period andassociated work activity exposure estimates that were likely to result in thehighest personnel collective exposures

• Site specific trends in collective exposures, plant historical data, and source-termmeasurements

• Site specific ALARA procedures

• Five work activities of highest exposure significance completed during the lastoutage

• ALARA work activity evaluations, exposure estimates, and exposure mitigationrequirements

• Intended versus actual work activity doses and the reasons for anyinconsistencies

• Integration of ALARA requirements into work procedure and radiation workpermit documents

• Shielding requests and dose/benefit analyses

• Post-work reviews

• Assumptions and basis for the current annual collective exposure estimate, themethodology for estimating work activity exposures, the intended dose outcome,and the accuracy of dose rate and man-hour estimates

• Use of engineering controls to achieve dose reductions and dose reductionbenefits afforded by shielding

• Self-assessments, audits, and special reports related to the ALARA programsince the last inspection

• Resolution through the corrective action process of problems identified throughpost-work reviews and post-outage ALARA report critiques

Enclosure-19-

• Corrective action documents related to the ALARA program and follow-upactivities such as initial problem identification, characterization, and tracking

The inspector completed 10 of the required 15 samples and 5 of the optional samples.

b. Findings


4. OTHER ACTIVITIES

4OA1 Performance Indicator Verification (71151)

.1 Barrier Integrity Cornerstone

a. Inspection Scope

The inspector reviewed a sample of the performance indicator (PI) data submitted bythe licensee regarding the barrier integrity cornerstone to verify that the licensee’s datawas reported in accordance with the requirements contained in NEI 99-02, "RegulatoryAssessment Indicator Guideline," Revision 3. The sample included data taken fromreactor coolant system water inventory Forms OPT-303-3 and the dose equivalentIodine-131 data from the Forms CHM-506-1, “Reactor Coolant System Control,Technical Specification, and Fuel Performance, Mode 1-3," Revision 26, for the periodJuly 2004 to March 2006 for both Units 1 and 2. The inspectors interviewed licenseepersonnel accountable for collecting and evaluating the PI data. The inspectorcompared this to the information available on the NRC web page for July 2004 to March2006 for both Units 1 and 2 for the following PIs:

• Units 1 and 2 Reactor Coolant System Activity• Units 1 and 2 Reactor Coolant System Leakage

The inspectors completed four samples in this cornerstone.

b. Findings


.2 Mitigation Systems Cornerstone

a. Inspection Scope

The inspector reviewed a sample of PI data submitted by the licensee regarding themitigating system cornerstone to verify that the licensee’s data was reported inaccordance with the requirements of NEI 99-02, “Regulatory Assessment PerformanceIndicator Guideline,” Revision 3. Reactor operator logs, limiting condition for operationaction requirement logs, SMF-2004-4109, SMF-2005-0094, SMF-2005-2587, SMF-2005-3675, SMF-2006-0011, SMF-2006-0981, and licensee event reports submittedbetween July 2004 and March 2006, were reviewed for both Units 1 and 2 to identify forthe following PI:

Enclosure-20-

• Units 1 and 2 Safety System Functional Failures

The inspectors completed two samples in this cornerstone.

b. Findings


.3 Occupational Radiation Safety Cornerstone

a. Inspection Scope

• Occupational Exposure Control Effectiveness

The inspector reviewed licensee documents from July 1, 2005, through March 31, 2006.The review included corrective action documentation that identified occurrences inlocked high radiation areas (as defined in the licensee’s Technical Specifications), veryhigh radiation areas (as defined in 10 CFR 20.1003), and unplanned personnelexposures (as defined in NEI 99-02). Additional records reviewed included ALARArecords and whole-body counts of selected individual exposures. The inspectorinterviewed licensee personnel that were accountable for collecting and evaluating PIdata. In addition, the inspector toured plant areas to verify that high radiation, lockedhigh radiation, and very high radiation areas were properly controlled. PI definitions andguidance contained in NEI 99-02, "Regulatory Assessment Indicator Guideline,"Revision 3, were used to verify the basis in reporting for each data element.

The inspector completed the required one sample in this cornerstone.

b. Findings

No findings of significance were identified. .4 Public Radiation Safety Cornerstone

a. Inspection Scope

• Radiological Effluent Technical Specification/Offsite Dose Calculation Manual Radiological Effluent Occurrences

The inspector reviewed licensee documents from July 1, 2005, through March 31, 2006.Licensee records reviewed included corrective action documentation that identifiedoccurrences for liquid or gaseous effluent releases that exceeded PI thresholds andthose reported to the NRC. The inspector interviewed licensee personnel that wereaccountable for collecting and evaluating the PI data. PI definitions and guidancecontained in NEI 99-02, "Regulatory Assessment Indicator Guideline," Revision 3, wereused to verify the basis in reporting for each data element.

The inspector completed the required one sample in this cornerstone.

Enclosure-21-

b. Findings


4OA2 Problem Identification and Resolution (71152)

.1 Review of Items Entered into the Corrective Action Program

a. Inspection Scope

As required by Inspection Procedure 71152, "Identification and Resolution of Problems,”and in order to help identify repetitive equipment failures or specific human performanceissues for followup, the inspectors performed a routine screening of all items enteredinto the licensee’s corrective action program. This review was accomplished byreviewing the licensee’s computerized corrective action program database SMFs,reviewing hard copies of selected SMFs and attending related meetings such as PlantEvent Review Committee (PERC) meetings.

b. Findings


.2 Semiannual Trend Review

a. Inspection Scope

On June 20, 2006, the inspectors completed a semiannual review of licensee internaldocuments, reports, and performance indicators to identify trends that might indicate theexistence of more safety significant issues. The inspectors reviewed the following typesof documents:

C Corrective Action Documents (Smart Forms)

C System Health Reports

C Planned Maintenance Work Week Critiques

C CPSES Nuclear Overview Department Evaluation Reports (Audits)

C Human Performance Program Health Indicators Package

C Corrective Action Program Health report

C Station Reliability Issues

C Degraded conditions evaluated in accordance with Generic Letter 91-18

C CPSES Self-Assessment Reports

Enclosure-22-

b. Findings and Observations

No findings of significance were identified. However, during the review, the inspectorsdid note trends or concerns that had been identified by the licensee and/or NRC whichwarrant continued attention. These included (1) foreign material exclusion, (2) use oferror prevention tools, (3) industrial safety practices, (4) radiation worker practices anddose management, and (5) change management, specifically in the area of work forceresources. The inspectors did not identify any additional trends.

The inspectors determined that the licensee had adequately identified adverse trendsand entered them into the corrective action program using an appropriate threshold.

.3 Selected Issue Followup - SMF-2004-002797-01, Engineering Evaluation of ModificationFailed to Identify Adverse Impact on Electrical Area and Primary Plant VentilationSystem Pressure Boundary

a. Inspection Scope

This issue was selected because it was a long term, licensee identified engineeringissue with some technical complexity, multiple cause determinations and a high level ofsignificance (level 2) within the CPSES corrective action program.

The inspectors assessed the licensee’s cause analysis using the inspection guidance inInspection Procedure 95001 as an aid. Other attributes assessed included: completeand accurate identification of the problem in a timely manner; evaluation and dispositionof operability and reportability issues; consideration of extent of condition, genericimplications, common cause, and previous occurrences; classification and prioritizationof the resolution of the problem; identification of root and contributing causes of theproblem; identification of corrective actions which were appropriately focused to correctthe problem; and completion of corrective actions in a timely manner commensuratewith the safety significance of the issue.

The inspector completed one sample.

b. Findings

No findings of significance were identified. During testing after implementing amodification to the Unit 1 main steam/feedwater area ventilation system, the licenseeidentified that some normal combinations of running fans caused a negative differentialpressure between the safeguards electrical area and the primary plant area. Thelicensee further determined that the ventilation systems may not be capable ofmaintaining the design differential pressures during a safety injection with a singlefailure to trip of a non-safety related train of main steam/feedwater area ventilation.

The licensee’s cause analysis stated that the original scope of the modification was tomake permanent a temporary modification which had already been reviewed forsignificant design impacts. The review did not consider that a non-safety related systemmay fail to trip or that a safety actuation on a single train could result in one train of non-safety ventilation continuing to run. A change to the modification during installation was

Enclosure-23-

not communicated to the engineer performing airflow analysis. Corrective actionsincluded changing the modification to eliminate the concern, correcting the associateddocumentation and conducting training based on the lessons learned.

.4 Radiation Safety Inspection

a. Inspection Scope

The inspector evaluated the effectiveness of the licensee’s problem identification andresolution process with respect to the following inspection areas:

• Access Control to Radiologically Significant Areas (Section 2OS1)• ALARA Planning and Controls (Section 2OS2)

b. Findings


.5 Maintenance Effectiveness Triennial Review

a. Inspection Scope

The inspectors evaluated the use of the corrective action program within theMaintenance Rule program. The review was accomplished by the examination of asample of corrective action documents and work orders. The purpose of the review wasto determine that the identification of problems and implementation of corrective actionswere acceptable.

b. Findings


4OA3 Event Followup (71153)

.1 (Closed) Licensee Event Report (LER) 05000445/2004-003-00 Reactor Coolant SystemLeak Detection Instrumentation Inoperable for Periods Due to a Design RelatedSiphoning Condition

On July 26, 2004, the licensee determined that the Unit 1 containment sump level andflow monitoring system had been inoperable on December 15, 2003, for a period greaterthan allowed by the Technical Specifications. The licensee determined that sumpinoperability was caused by an original design flaw in system piping elevations thatallowed the containment sumps to be siphoned to the floor drain tank. Corrective actionconsisted of a system modification to add vacuum breakers to eliminate siphoningevents. No new findings were identified by the inspector’s review. This findingconstitutes a violation of minor significance that is not subject to enforcement action inaccordance with Section IV of the NRC’s Enforcement Policy. The licensee hasdocumented this issue in SMF-2004-002244-00. This LER is closed.

.2 (Closed) LER 05000446/2005-001-00 Unit 2 Containment Personnel Airlock DoorInoperable for a Period of Time Longer than Allowed by Technical Specifications

Enclosure-24-

On January 18, 2005, the licensee identified that one of the two Unit 2 containmentpersonnel airlock doors had been inoperable for a period of time longer than allowed bythe Technical Specifications. The engineering staff determined that the airlock doorswere inoperable because the doors gaskets on both doors had been improperly installedbecause of an inadequate procedure. Corrective actions included installing the doorgaskets correctly and revising procedures for installing the gaskets andpostmaintenance testing. No new findings were identified by the inspector’s review. This finding constitutes a violation of minor significance that is not subject toenforcement action in accordance with Section IV of the NRC’s Enforcement Policy. The licensee has documented this issue in SMF-2004-004007-00. This LER is closed.

.3 (Closed) LER 05000446/2005-002-00 Auxiliary Feedwater System Actuation Due toMomentary Loss of the 138KV Switchyard

On February 23, 2005, at 1:53 a.m., a momentary interruption of power to the 138KVswitchyard occurred causing the Unit 2 6.9KV safeguards buses to transfer to theiralternate power source. This resulted in actuation of the Unit 2 black out sequencersand actuation of the turbine driven auxiliary feedwater pump, as expected. The licensee believed the event was caused by a lightning strike on the Stephenville transmission lineand a misconfigured jumper in the power line communication equipment located at theDeCordova end of the other transmission line. The jumper configuration was correctedand the transmission company verified the jumper settings at other adjacentswitchyards. The LER was reviewed by the inspectors and no findings of significancewere identified and no violations of NRC requirements occurred. This event wasdocumented in Section 1R14 of NRC Inspection Report 05000445;446/2005002 and bythe licensee in SMF-2005-000722-00. This LER is closed.

4OA5 Other Activities

.1 (Closed) Unresolved Item (URI) 05000445;05000446/2005005-02: Notification FormAccuracy Requires Additional Guidance

a. Inspection Scope

The inspector previously reviewed data supporting licensee submittals for the Drill andExercise performance indicator for the period July 2004 through September 2005, andidentified 11 instances in which the licensee evaluated offsite notification forms asaccurate when a site-wide emergency condition was marked as applying only to Unit 1. The inspector reviewed Frequently Asked Question #58.2, approved by thePerformance Indicator Joint Working Group on February 23, 2006, and determined thelicensee was required to provide guidance for evaluating all aspects of notificationaccuracy, but was not required to revise previously submitted performance indicatordata. The inspector determined that the licensee did not revise previously submittedperformance indicator for the period July 2004 through September 2005.

b. Findings


Enclosure-25-

.2 (Closed) URI 05000445; 05000446/2005008-01: Operators Unable to Meet SomeCritical Action Times During Alternative Shutdown Walkthrough

Introduction. The team identified a Green noncited violation of License Condition 2.Gand Technical Specification 5.4.1.d with five examples for failure to complete simulatedoperator actions within analyzed times and for the inability to perform some of therequired actions. The licensee entered this item into their corrective action program.

Description. The team identified the following examples of inadequate proceduralguidance for achieving post-fire safe shutdown following evacuation of the control roomby performing reviews and timed walkthroughs of procedure ABN-803B, “Response ToA Fire In The Control Room or Cable Spreading Room," Revision 3.

A walkthrough of Procedure ABN-803B was timed by the NRC regional inspectors toobserve the actions of the shift manager/unit supervisor, licensed control roomoperators and non-licensed plant equipment operators. The shift manager wasunfamiliar with the location of keys needed to gain access to the transfer panels and hotshutdown panels. As a result, the crews of both units would have been delayed intransferring control. Without access to the hot shutdown panel and the transfer switchpanel, the mitigation of spurious actuations because of fire damage would not havebeen accomplished. The licensee has modified the “Controlled Keys" key locker toreplace the locking mechanism with a door latch and provided additional labeling to aidin locating the safe shutdown keys. Operations shift orders were issued to train theoperators on this issue and resulting changes.

During a timed performance of the alternate shutdown Procedure ABN-803B by NRCinspectors, approximately 1.5 minutes were required to perform the steps inside thecontrol room prior to evacuation from the control room. The licensee verification andvalidation of procedure ABN-803B did not account for the time that the operators needto perform their actions in the control room. This was inconsistent with the fire safeshutdown analysis. The safe shutdown analysis specified that operators must takeactions to mitigate a spuriously open power operated relief valve within 3 minutes. However, the team observed that it took 4 minutes to accomplish these actions (notaccounting for the delay in obtaining keys).

During the timed walk down of Procedure ABN-803B with plant operators, it was notedthat in Procedure ABN-803B, Attachment 4, Step l required the plant operator to ensurethat the safety chiller was operating. The procedure did not provide the operatorspecific directions for restarting the safety chiller if not already running. The teamobserved that the equipment operator was unable to perform that step because of thelack of procedural detail. Without the chiller operating, all personnel, all runningemergency core cooling system motors, and the sole operating emergency dieselgenerator would be subjected to elevated temperatures because of ventilation withoutcooling.

Procedure ABN-803B also did not adequately address potential fire damage to thepublic address and fire alarm systems in the event of a fire in the control room. Thedesign basis document for the communication system stated that for a control room fire,the Gai-Tronics system could become inoperable. Procedure ABN-803B required theshift manager to make an announcement using the “All Page" function of the Gai-Tronics station in the control room, and to sound the fire alarm from the same location.

Enclosure-26-

The alternate station for the "All Page" function was the Technical Support Center. However, the Technical Support Center would be uninhabitable during a control roomfire because it used the same ventilation system.

Licensee policy required the donning of flash protective gear when operating energizedbreakers in high voltage switchgear. The plant equipment operators were required toopen the four reactor coolant pump breakers and to open the startup transformerbreaker to mitigate the effects of spurious actuations. These were 6.9 kV breakers andwould be energized and loaded during the performance of this procedure. Theinspectors determined that the 3.5 minutes required for the plant equipment operator todon the protective gear and continue with the procedure did not allow accomplishmentof subsequent actions within the times defined by the safe shutdown analysis.

Analysis. The team determined that this finding had more than minor significancebecause the inadequate procedure impacted the mitigating systems cornerstone andaffected the cornerstone objective to ensure the availability, reliability, and capability ofthe system that responds to the event to prevent undesirable consequences. A Phase 3analysis of the above issues concluded the finding was of very low risk significance. Specifically, the Phase 3 analysis concluded that the 8-minute delay in transferringequipment from the control room and an additional 10-minute delay in accessing theremote shutdown room, did not result in a significant increase in risk. The analystdetermined that a hot-short to a power operated relief valve was the most risk significantsituation. The risk associated with a stuck open power-operated relief valve combinedwith a fire in the control room panel not suppressed was determined to be 2.7E-11/year.

The analyst concluded that it would require a 22 percent increase in operator failurerates to result in the risk exceeding the threshold to be considered greater than that ofvery low risk significance. Human reliability models were not available to quantify theeffect of the initial problems that would be encountered during the control roomevacuation, but as an estimate, the analyst determined that the increased stress (whichwould be small because the baseline stress of any control room evacuation is very high)and 10-minute time loss in performing actions would not increase the failure rate ofremote shutdown by more than 22 percent overall.

The cause of the finding is related to the crosscutting aspect of human performancebecause (1) operations personnel were unfamiliar with procedures and did not havesome pertinent procedure steps available, and (2) organizations failed to communicatechanges to the procedure that impacted the response time.

Enforcement. License Condition 2.G specifies, "TXU Generation Company LP shallimplement and maintain in effect all provisions of the approved fire protection programas described in the Final Safety Analysis Report through Amendment 78 and asapproved in the safety evaluation report (SER) (NUREG-0797) and its supplementsthrough 24." Technical Specification 5.4.1.d requires that written procedures coveringfire protection program implementation be established, implemented, and maintained. Procedure ABN-803B, "Response To A Fire In The Control Room or Cable SpreadingRoom," Revision 3, described required time-dependent actions for evacuating thecontrol room. Contrary to the above, the inspectors determined that the procedurefailed to ensure that all time-dependent actions could be accomplished in the timeassumed in the analysis and/or could be accomplished. Specifically, the followingdeficiencies were identified: (1) the shift manager was unable to easily obtain the keys

Enclosure-27-

needed to access the transfer and hot shutdown panels, which delayed taking therequired actions; (2) directions for starting the safety chiller, if not already operating,were not provided, which could have delayed accomplishing the task; (3) the licenseehad not accounted for 1.5 minutes needed by operators to perform required actionsprior to evacuating the control room; (4) operators took 4 minutes to mitigate aspuriously open power-operated relief valve, whereas the analysis used 3 minutes;and (5) the 3.5 minutes needed to don the flash protective gear prevented completion ofsubsequent procedure steps within the time analyzed.

The licensee attributed root cause to a failure of operations to coordinate a revisedsafety requirement with plant personnel who understood the potential impact on thealternate shutdown time line. As immediate corrective actions, the licensee evaluatedtheir time line and determined that sufficient margin existed and that the actions couldbe accomplished. The licensee initiated SMF-2005-000316-00 to take the appropriatecorrective actions. Because this violation was determined to be of very low safetysignificance, it is being treated as a noncited violation, consistent with Section VI.A.1 ofthe NRC Enforcement Policy: NCV 05000445;446/2006003-02 Operators Unable toMeet Some Critical Action Times During Alternative Shutdown Walkthrough.

.3 Implementation of Temporary Instruction (TI) 2515/165 - Operational Readiness ofOffsite Power and Impact on Plant Risk

a. Inspection Scope

The objective of TI 2515/165, “Operational Readiness of Offsite Power and Impact onPlant Risk,” was to confirm, through inspections and interviews, the operationalreadiness of offsite power systems in accordance with NRC requirements. On March 13through 17, 2006, the inspectors reviewed licensee procedures and discussed theattributes identified in TI 2515/165 with licensee personnel. In accordance with therequirements of TI 2515/165, the inspectors evaluated the licensee’s operatingprocedures used to assure the functionality/operability of the offsite power system, aswell as, the risk assessment, emergent work, and/or grid reliability procedures used toassess the operability and readiness of the offsite power system.

The information gathered while completing this Temporary Instruction was forwarded tothe Office of Nuclear Reactor Regulation for further review and evaluation.

b. Findings


4OA6 Meetings, Including Exit

Exit Meeting Summary

On April 10, 2006, the inspector conducted a telephonic exit meeting to present theemergency preparedness inspection results to Mr. M. Bozeman, Supervisor, EmergencyPlanning, who acknowledged the findings. The inspector confirmed that proprietaryinformation was not provided or examined during the inspection.

Enclosure-28-

On May 19, 2006, the inspector presented the occupational radiation safety inspectionresults to Mr. M. Kanavos, Plant Manager, and other members of his staff whoacknowledged the findings. The inspector confirmed that proprietary information wasnot provided or examined during the inspection.

On May 22, 2006, the inspector presented the results of the notification form accuracyunresolved item closure to Mr. R. Kidwell, Licensing Engineer, who acknowledged thefindings.

On May 22, 2006, the inspector discussed the results of the licensed operatorrequalification program inspection with Mr. Gary Struble, Operations TrainingSupervisor. The licensee acknowledged the findings presented. The inspector askedthe licensee whether any materials examined during the inspection should beconsidered proprietary. No proprietary information was identified.

On May 25, 2006, the inspector presented the maintenance effectiveness triennial inspection results to Mr. P.M. Polefrone, Plant Manager, and other members of licenseemanagement at the conclusion of the onsite inspection. The inspector verified that noproprietary information was reviewed during the inspection.

On May 25, 2006, the inspector conducted a telephonic exit meeting with Mr. FredMadden, Director, Regulatory Affairs, to discuss the significance of the finding thatresulted from closeout of the alternative shutdown walkthrough unresolved item.

On June 29, 2006, the inspectors presented the resident inspection results toMr. M. Blevins, Senior Vice President and Chief Nuclear Officer, and other members oflicensee management. The inspectors confirmed that proprietary information was notprovided or examined during the inspection.

ATTACHMENT: SUPPLEMENTAL INFORMATION

EnclosureA-1

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

J. Alldredge, Supervisor, Radiation ProtectionM. Blevins, Senior Vice President and Chief Nuclear OfficerD. Bozeman, Manager, Emergency PlanningS. Bradley, Supervisor, Health Physics, Radiation Protection & Safety ServicesT. Clouser, Manager, Shift OperationsJ. Curtis, Radiation Protection Manager, Radiation and Industrial SafetyD. Ellis, Level III Qualified Data AnalystR. Flores, Vice President, Nuclear OperationsM. Kanavos, Plant ManagerS. Karpyak, Risk & Reliability Engineering SupervisorR. Kidwell, Licensing EngineerB. Knowles, Supervisor, Radiation ProtectionD. Kross, Director, MaintenanceJ. Lamarca, Engineering Smart Team ManagerM. Lucas, Vice President Nuclear EngineeringF. Madden, Director, Regulatory AffairsJ. Mercer, Maintenance Rule Coordinator J. Meyer, Technical Support ManagerW. Morrison, Maintenance Smart Team ManagerP. Polefrone, Plant MangerV. Polizzi, Steam Generator Programs EngineerL. Pope, System EngineerR. Smith, Director, OperationsS. Smith, Director, System EngineeringG. Struble, Operations Training SupervisorJ. Taylor, Engineering Smart Team ManagerC. Tran, Engineering Programs ManagerD. Wilder, Radiation and Industrial Safety Manager

NRC

D. Allen, Senior Resident InspectorA. Sanchez, Resident Inspector

ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

None

Opened and Closed

05000445;446/2006003-01 NCV Three Examples of a Failure to Conspicuously Post aRadiation Area (Section 2OS1)

EnclosureA-2

05000445;446/2006003-02 NCV Operators Unable to Meet Some Critical Action TimesDuring Alternative Shutdown Walkthrough(Section 4OA5.2)

Closed

05000445/2004-003-00 LER Reactor Coolant System Leak Detection InstrumentationInoperable for Periods Due to a Design Related SiphoningCondition (Section 4OA3.1)

05000446/2005-001-00 LER Unit 2 Containment Personnel Airlock Door Inoperable fora Period of Time Longer than Allowed by TechnicalSpecifications (Section 4OA3.2)

05000446/2005-002-00 LER Auxiliary Feedwater System Actuation Due to MomentaryLoss of the 138KV Switchyard (Section 4OA3.3)

05000445;446/2005005-02 URI Notification Form Accuracy Requires Additional Guidance(Section 4OA5.1)

05000445;446/2005008-01 URI Operators Unable to Meet Some Critical Action TimesDuring Alternative Shutdown Walkthrough(Section 4OA5.2)

Discussed

None

LIST OF DOCUMENTS REVIEWED

Section 1R05: Fire Protection

STA-729, Control of Transient Combustibles, Ignition Sources and Fire Watches, Revision 7

STA-738, Fire Protection System/Equipment Impairments, Revision 6

FPI-101A, Unit 1 Safeguards Building Elevation 773'-0" Train “A” & “B” - RHR, SI & CS PumpRooms, Revision 3

FPI-102A, Unit 1 Safeguards Building Elevation 790'-6", Revision 3

FPI-103A, Unit 1 Safeguards Building Elevation 810'-6" Rad. Pen. Area & Elec. Equip Rooms,Revision 3

FPI-106A, Unit 1 Safeguards Building Elevation 831'-6" Main Corridor, RB Access, & ElectricalEquipment Area, Revision 4

FPI-401, Auxiliary Building Elevation 790'-6", Revision 3

EnclosureA-3

Section 1R06: Flood Protection

STA-696, Hazard Barrier Controls, Revision 250.50 Screen 59SC-2004-001702-08-00SMF-2004-002217-00EVAL-2004-002217-01-00SMF-2005-002127-0059SC-2005-002127-01-00FDA-2005-002127-01-00SMF-2005-003667-00EVAL-2005-003667-01-00

Section 1R12: Maintenance Effectiveness- Routine

SMF-2006-000302-00SMF-2006-000640-01SMF-2006-000707-00SMF-2006-001702-00SMF-2006-001206-00SMF-2006-001290-00SMF-2006-001344-00SMF-2006-002133-00SMF-2004-003379-00CPSES System Status Report for 1st Quarter FY06CPSES System Status Report for 4th Quarter FY05STA-744, “Maintenance Effectiveness Monitoring Program,” Revision 3

Section 1R12: Maintenance Effectiveness- Triennial

Smart Forms

2004-000566-002004-003610-002005-000228-002005-002654-002005-003804-002006-000125-002006-001356-002006-000946-002005-003342-00

2005-003238-002005-003235-002005-003531-002005-004280-002005-000972-002005-000971-002005-000206-002004-003985-00

2004-003984-002005-002633-002005-000085-002005-002399-002005-003087-012005-003350-002005-003967-002005-002313-00

Procedures

"Performance Criteria Guide for Monitoring Maintenance Effectiveness,” Revision 6, datedFebruary 27, 2004

"Maintenance Effectiveness Monitoring Program, Maintenance Rule Review Panel GuidanceDocument,” Revision 2, dated April 6, 1998

"Goal Setting and Monitoring Guide,” Revision 3, dated February 26, 2004

EnclosureA-4

"Maintenance Preventable Functional Failure Guide,” Revision 4, dated May 23, 1999

OPT-443A, "Reactor Trip Breaker and Stationary Gripper Coil Response Time," Revision 3

STA-744, "Maintenance Effectiveness Monitoring Program," Revision 2, dated November 25,1999

"Comanche Peak Performance Report," February 2005

"Maintenance Rule Function," February 27, 2006

"System Performance Criteria," October 29, 2004

Evaluations

EVAL-2001-002576-03-02EVAL-2004-000427-01-00EVAL-2004-003610-00EVAL-2005-000085-05-00EVAL-2005-000105-02-01

EVAL-2005-000164-01-00EVAL-2005-000228-01-00EVAL-2005-002399-00EVAL-2005-002633-01-00

EVAL-2005-002654-01-00EVAL-2005-003804-01-00EVAL-2006-000125-01-00EVAL-2006-000287-02-00

Drawings

M1-0229, Sheet A, Flow Diagram Component Cooling Water SystemM1-0230, Flow Diagram Component Cooling Water SystemM1-0234, Flow Diagram Station Service Water SystemM1-0206, Flow Diagram Auxiliary Feedwater SystemM1-0230, Sheet A, Flow Diagram Component Cooling Water SystemM1-0229, Sheet B, Flow Diagram Component Cooling Water SystemM1-0233, Flow Diagram Station Service Water System

Miscellaneous

"Investigation of Failed Volume Booster Relays,” Southwest Research Institute, submitted toTXU, October, 2005

SA-2004-044, "Maintenance Rule Periodic Assessment #6," February 17, 2005

01-020-259, "Determination of Adequacy of Line Shaft Bearing Lube Water Flow," datedJanuary 4, 2006

Section 1R15: Operability Evaluations

SMF-2006-001674-00WO 5-06-505058-ABWO 5-06-505058-ACWO 5-06-505058-AD

EnclosureA-5

Section 2OS1: Access Controls to Radiologically Significant Areas

Smart Forms

2005-3627, 2006-144, 2006-1787

Procedures

NQA-3.02 Audit and Surveillance Programs, Revision 2RPI-602 Radiological Surveillance and Posting, Revision 27STA-660 Control of High Radiation Areas, Revision 9

Section 2OS2: ALARA Planning and Controls

Smart Forms

2005-4217, 2006-1762, 2006-1770, 2006-1795, 2006-1781

Audits and Self-Assessments

EVAL-2005-010 Annual Radiation Protection AuditSA-2006-004 Radiation Protection Training ProgramSA-2005-059 Analysis of Personnel Contaminations during 1RF11

Shielding Requests

06-03, 06-12, 06-13

Radiation Work Permits

2005-1210 1RF11 Work Activities in Lower Loop Room 1/4 Room 1-154 I/L2005-1212 1RF11 Work Activities in 808' West Corridor Loop 1/4 Room 1-154 A/D2005-1300 N-1 Steam Generator Walkdowns2005-1308 Loop Room Scaffolding2005-1600 Refueling Activities During 1RF112006-24 Containment Entry to perform minor maintenance during Modes 1 and 22006-0221 Operations Valve Position Verifications2006-0224 GSI-191 Unit 1 and 2 Laser Templating and Rebar Scanning

Procedures

STA-302 Station Records, Revision 20STA-650 General Health Physics Plan, Revision 5STA-655 Exposure Monitoring Program, Revision 14STA-656 Radiation Work Control, Revision 12RPI-606 Radiation Work and General Access Permits, Revision 14RPI-608 Control of Shielding, Revision 8

Miscellaneous

ALARA Review Committee Meeting Minutes, July 5, 2005, through February 23, 2006.

EnclosureA-6

Section 4OA1: Performance Indicator Verification

Procedures

Radiation Safety NRC Performance Indicators Job Aide, Definitions, and Flow Chart,February 14, 2006

Section 4OA2.2: Semiannual Trend Review

Self-Assessment and Benchmarking Program Health Report- 1St Quarter 2006

CPSES Self-Assessment Report SA-2005-048, Operator Fundamentals

CPSES Self-Assessment Report SA-2005-026, Focused Self-Assessment of EngineeringHuman Performance Program Implementation

CPSES Self-Assessment Report SA-2005-060, Margin Management/ConfigurationManagement Implementation in Engineering

Human Performance Program Health Indicators Package - 1st Quarter 2006

Center of Excellence 1st Quarter Site Roll-up and Trending Report

Section 4OA2.3: Selected Issue Followup - SMF-2004-002797-01

FDA-1999-003133EVAL-1999-003133-09-00EVAL-2004-002720-01-0159SC-2004-002720-01-00SMF-2004-002797-01EVAL-2004-002797-01-02SMF-2004-003724-00EVAL-2004-003724-01-00DBD-ME-302B, “Electrical Area Ventilation System,” Revision 13DBD-ME-302C, “Main Steam and Feedwater Area Ventilation System,” Revision 10

Section 4OA5: Temporary Instruction TI 2515/165

ABN-601, Response to a 138/345 KV System Malfunction, Revision 9IPO-003A/B, Power Operations, Revisions 24/15STA-604, Configuration Risk Management and Work Scheduling, Revision 6STA-629, Switchyard Control, Revision 4WCI-203, Weekly Surveillances / Work Scheduling, Revision 19

EnclosureA-7

LIST OF ACRONYMS

ABN abnormal conditions procedure

ALARA as low as reasonably achievable

CCW component cooling water

CFR Code of Federal Regulations

CPSES Comanche Peak Steam Electric Station

EDG emergency diesel generator

ERCOT Electric Reliability Council of Texas

EVAL evaluation

I/P current to pneumatic

INC instrument and control manual

LER licensee event report

NCV noncited violation

NEI Nuclear Energy Institute

NRC Nuclear Regulatory Commission

NUC nuclear engineering manual

OPT operations testing manual

PAR protective action recommendation

PERC plant event review committee

PI performance indicator

SDP significance determination process

SIP safety injection pump

SMF smart form

SOP system operating procedure

SSC structures, systems, or components

TDAFW turbine driven auxiliary feed water

TI temporary instruction

URI unresolved item

EnclosureA-8

and Chief Nuclear Officer TXU Power ATTN: Regulatory ... · July 22, 2006 Mike Blevins, Senior Vice...

Documents

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